Method of recovering oil from an oil-bearing reservoir



FREE GAS SATURATION PERCENT FIG. 2.

CARL CONNALLY, JR.

LORLD G. SHARP INVENToR.

B1', Rmx@ ATTORNEY.

United States Patent O 3,157,230 METHGD F RECOVERING OIL FROM ANOIL-BEARING RESERVOIR Carl Connally, Jr., Dallas, and Lorid G. Sharp,Irving,

Tex., assignors to Socony Mobil Oil Company, Inc., a

corporation of New York Filed Dec. 16, 1960, Ser. No. 76,322 4 Claims.(Cl. 166-9) formation to the Surface through a well penetrating theformation. This method of oil production is commonly referred to asprimary recovery. The native reservoir energy utilized in primaryrecovery may exist in the form of water, gas cap, or solution-gas drive,either singularly or in combinations thereof. These various forms ofenergy inherent in most newly penetrated oil-bearing formations providethe driving force for the removal of the oil without the necessity ofproviding energy from a source foreign to the formation. When the nativereservoir energy of a formation is depleted or nearly depleted, it iscommon practice to apply secondary recovery methods which comprise theaddition of energy from outside sources for the purpose of increasingthe ultimate recovery of oil from the formation.

Many different forms of secondary recovery methods have been eitheractually employed or proposed. For example, probably the more commonmethods involve the introduction of water or gas through an injectionwell leading to the formation for the purpose of driving the remainingoil in the formation to a producing well. In some instances, Water andgas have been used alternately. Among the numerous proposals, thefollowing are typical examples of what has been suggested forintroduction into a formation to improve the ultimate recovery of oil:liquefied petroleum gas and gas or enriched gas followed by either wateralone or water and gas alternately; alternate slugs of liquefiedpetroleum gas and water; dry gas, followed by gas inriched with liquidpropane and ethane, followed by ethane and propane, followed by water;liquefied petroleum gas, followed by gas; a liquefied petroleum gas slugalone; water, followed by a liquefied petroleum gas slug, followed bygas; and water, followed by a liquefied petroleum gas slug, followed bygas, followed by water.

It is to be noted that many of the above-suggested procedures ofsecondary recovery involve the use of liquefied, normally gaseoushydrocarbons such as liquefied petroleum gas. There is much disagreementas to the amount of liquefied petroleum gas which is needed to mostefficiently produce oil remaining in a formation after the completion ofprimary recovery. Also, methods which employ liquefied petroleum gasesare expensive operations. In View of the uncertainness of the amount ofliquefied petroleum gas needed and its cost, the procedures using ithave been rejected sometimes in favor of the commonly used water-floodoperations which, while they may produce less oil, may be moreeconomical.

We have found that during primary recovery such as a solution-gas drive,a well may be produced until an optimum range of conditions of free-gassaturation exists within the formation, at which time a minimum amountof hydrocarbon material which is miscible with the oil the misciblehydrocarbon material are driven through the 3,157,230 Patented Nov. 17,1964 and gas in the formation may be introduced to obtain maximum oilrecovery from the formation. Fundamentally, the present invention isneither a primary recovery process nor a secondary recovery process, butrather is a combination of the two processes, directed to the recoveryof a maximum amount of oil from a formation with a minimum amount ofmiscible material being injected into the formation.

It is an object of this invention to provide a method of recovering oilfrom an oil-bearing reservoir. It is another object of this invention toprovide a method of coordinating a primary recovery process with amiscible flood form of secondary recovery process in order to effectrecovery of a maximum amount of oil from an oilbearing reservoir. It isa further object of this invention to provide a method of combining aprimary recovery process with a miscible flood process wherein a minimumamount of miscible hydrocarbon material is required to obtain a maximumamount of oil recovery from a formation. These and further objects andadvantages of this invention will become apparent from a reading of thefollowing description, taken in conjunction with the drawings.` /mrdancewith the invention, an oil-bearing reservoir is produced from at leastone outlet well by pri- V,mary recovery methods until the free-gassaturation in the reservoir has increased to within a predeterminedrange, preferably about 15 percent to about 30 percent of ,thehydrocarbon pore volume of the reservoir. When the g'stated degree offree-gas saturation has been obtained, a

'quantity of hydrocarbon material which is miscible with the oil and thegas in the reservoir is introduced into the greservoir through at leastone input well. This miscible material is followed by the introductionof a driving fluid into the formation through the input well. The oiland formation toward the outlet well by the driving fluid until oil andgas are produced from the outlet well.

A producing reservoir, that is, one which is capable of being producedby solution-gas drive, normally in its virgin state contains fluid inessentially one liquid oil phase. This liquid oil phase consists ofvarious molecular weight hydrocarbons, each of which under normalatmospheric conditions is either in the gaseous or liquid state. Thereservoir, therefore, consists of normally gaseous hydrocarbons whichare dissolved in normally liquid hydrocarbons. The liquid found in sucha reservoir possesses a property known as its original saturationpressure. The original saturation pressure is the pressure above whichall of the hydrocarbons will remain in the liquid phase, that is, abovethis pressure the normally gaseous hydrocarbons remain dissolved in thenormally liquid hydrocarbons. Originally, the reservoir pressure may befar in excess of the saturation pressure of the liquid found in thereservoir. When, under such conditions, the reservoir liquid ispermitted to flow from the reservoir through an outlet well, the liquidtends to expand with decrease in pressure, driving some of the reservoiroil out through the outlet well. Such a form of production is known asliquid expansion. After such reservoirs have been produced by liquidexpansion for some period of time, the reservoir pressure willeventually decrease to the point where it will equal the saturationpressure of the liquid in the reservoir. At the time when the reservoirpressure is equal to the saturation pressure of the liquid in thereservoir, the liquid is said to be saturated, and therefore any furtherreduction in the reservoir pressure will result in the existence of freegas within the reservoir. As gas escapes from solution and becomes freegas, it occupies a larger volume than when it was dissolved in the oil.The increased Volume, occupied by gas escaping from solution, drivesboth oil and gas from the reservoir through the outlet well. Such a formof production is known as solution-gas drive. As the reservoir ispermitted to further produce by solution-gas drive, this free gas willincrease in amount.

For purposes of definition, the term hydrocarbon pore volume as usedherein means that volume of the pore space in a reservoir which wasoriginally occupied by hydrocarbons, whether in the gaseous or liquid,or both phases. It is to be understood that such definition does notcontemplate the existence of a gas cap, and should such exist within areservoir its Volume would not be taken into considera-tion in thedetermination of the hydrocarbon pore volume of the reservoir.

The term free-gas saturation as used herein refers to the percentage ofthe hydrocarbon pore volume occupied by a gas in the free state. Forexample, if a reservoir is produced by solution-gas drive until thefree-gas saturation is 15 percent, that portion of the reservoir whichoriginally was filled with hydrocarbons in the liquid state is nowoccupied by hydrocarbons in the liquid state and hydrocarbons in thefree-gaseous state, with the hydrocarbons in the free-gaseous statecomprising 15 percent and the hydrocarbons in the liquid statecomprising the remaining 85 percent.

A normal hydrocarbon-bearing reservoir is usually occupied also bywater. The presence or absence of water,

' however, does not affect the processes of the present invention sinceby definition the hydrocarbon pore volume is that portion of thereservoir originally occupied by hydrocarbon, not Water, and thepercentage of free-gas saturation is that portion of the hydrocarbonpore volume of the reservoir occupied by gas in the free state at aparticular stage in the production of oil from the reservoir.

Referring to the drawings, FIGURE 1 is a diagrammatic representation ofan oil-bearing reservoir penetrated by at least one inlet well and oneoutlet well. FIGURE 2 shows a series of curves illustrating the range offree-gas saturation in which a minimum volume of miscible material maybe employed in accordance with the invention.

Referring to FIGURE 1 of the drawings, the reference numeral denotes thehydrocarbon-bearing portion of a producing reservoir at a stage in theprocess of the invention when a slug 4of miscible material and a drivinggas have been established in the reservoir. Portion 11 of the reservoiris that portion of the reservoir which contains what remains of theoriginal liquid and gaseous hydrocarbons. For example, portion 11 mayhave a freegas Isaturation of 20 percent, which means that 20 percent ofthe pore space occupied by hydrocarbons in the formation of portion 11is occupied by gas in a free state, while 80 percent of portion 11 isoccupied by hydrocarbons in a liquid state. The liquid hydrocarbons inportion 11 will contain some gas in the dissolved state. It will beunderstood by those skilled in the art that there is no clear line ofdemarcation in portion 11 between the zones containing the gas in thefree state and liquid hydrocarbons. The free gas and the liquidhydrocarbons within portion 11 will be intermixed. Portion 12 ofreservoir 10, as shown, is occupied by a slug of miscible materialwhich, as hereinafter explained, may be either in the liquid or gaseousstate. Though the line of division between portion 11 and portion 12 isclearly ixed geometrically in FIGURE 1, it will be readily understoodthat in actual practice this is not a clear line of division inasmuch asthere will be some lingering of the slug of miscible material into thehydrocarbons of portion 11 and there will be a zone of transitionbetween the material in portion 11 and that in portion 12 wherein theslug of miscible material is intermixing with the hydrocarbons inportion 11. Portion 13 of reservoir 10 is shown as being lled withdriving fluid. Wells 14 and 15, as shown, penetrate reservoir 10. In theinitial phase of the process of the invention, wells 14 and 15 may bothfunction as producing wells. On the other hand, only one of these wellsmay, if desired, be used as a producing well. In the later stages of theprocess of this invention, one of wells 14 and 15 will be established asan outlet Well, while the other well is established as an inlet orinjection Well.

The first, or initial, phase of the process of our invention comprisesthe production of an oil-bearing reservoir through at least one well byprimary production methods. The pressure within reservoir 10 is above1000 p.s.i. and may be above 2000 p.s.i. or even higher. The temperaturewithin the formation may range from about 75 F. to about 250 F. or evenhigher. Initial production from reservoir 10 may be accomplished througheither, or both, wells 14 and 15 by free flow such as liquid expansionand solution-gas drive, if the pressure within the reservoir is suicientto effect the desired liow from the reservoir through these wells. Ifthe pressure of the reservoir is not suicient for such means ofproduction, production may be effected by pumping, by gas lift, or byother assist methods. This first step in our process is continued untilreservoir pressure is decreased to the extent that the free-gassaturation of the reservoir has increased to a value in the range ofabout 15 perecnt to about 30 percent by volume of `the hydrocarbon porespace in the reservoir. The percentage of free-gas saturation may bereadily determined lby means Well known to those skilled in the art,such as by material balance calculations and laboratory studies of theformation oil and gas phase-behavior. When the desired percentge rangeof free-gas saturation within the reservoir has been established byprimary production methods, the second step, or phase, of our processmay be initiated.

In the second step of the process of our invention, at least one wellpenetrating the oil-bearing reservoir acts as a producing or outletwell, while at least one other well penetrating the reservoir acts as aninlet or injection well. In the example illustrated in FIGURE 1 of thedrawings, well 14 functions as a producing Well while well 15 serves asan injection well. The second step of our process comprises establishinga zone of miscible fluid in the reservoir between the production welland the injection well. In FIGURE 1, this miscible Huid is representedas occupying portion 12 of the reservoir behind portion 11, which isociupied by the hydrocarbons to be produced by the process of ourinvention. This miscible iluid is often referred to by those skilled inthe art as a miscible slug. The miscible slug shown in portion 12comprises, in the preferred embodiment of the invention, hydrocarbonmaterial which exists in the liquid state or as a single phase fluid atthe reservoir pressure, though it is to be understood that this miscibleslug may also be what is referred to as an enriched gas. The miscibleslug in portion 12 of the reservoir is established by introduction ofthe hydrocarbon material into the reservoir through injection well 1S.

The material comprising the miscible slug may be a hydrocarbon iluidwhich is miscible with the oil and gas in the formation, such as anenriched gas, or liqueed, normally gaseous hydrocarbons, such asliqueiied petroleum gas. The introduction of the miscible slug is madeat pressures sutiicient to establish and maintain it as a single-phasefluid slug which is miscible with the oil and gas in the reservoir. Thematerial comprising the slug to be established in the reservoir may alsoexist as a liquid hydrocarbon containing from two to live carbon atomsper molecule and not more than trace amounts of higher molecular weighthydrocarbons. The injection pressures of this latter material must, ofcourse, be such that the material will be maintained as a liquid in thereservoir. Also, it is to be understood that this miscible slug maycomprise ethane, propane, butane, or pentane, or mixtures of these, orliquelied petroleum gas consisting of a mixture of relatively minoramounts of ethane, larger amounts of propane and butane, with a minoramount of pentane, and not more than trace amounts of hexane and highermolecular weight hydrocarbons with the total amount of hexane and highermolecular Weight hydrocarbons comprising generally less than about twomol percent of the liquefied petroleum gas mixture forming the slug. Itis to be further understood that the miscible slug may also comprise anenriched gas formed of methane of not more than 40 mol percent, ethaneof not more than 30 mol percent, with the remainder of the blend beingcomprised of higher molecular weight saturated hydrocarbons of not morethan five carbon atoms with trace amounts of hexane and higher molecularweight saturated hydrocarbons. The miscible slug may also comprise amiscible gas formed of ethane, propane, and butanes existing as asingle-phase gas in a reservoir which obtains a temperature higher thanthe critical temperature of the mixture, or any of the above purehydrocarbons which would be directly miscible may be employed.

The amount of hydrocarbon material making up the miscible slugpreferably is in the range of about 1 to l0 percent of the hydrocarbonpore volume of the reservoir to be swept by the slug. Several conditionsof the reservoir are factors which operate to control the amount ofhydrocarbon material making up the slug. Some of these conditions whichhave been recognized as factors controlling the amount of materialrequired for the slug are as follows: relative permeabilities andporosities of different zones of the reservoir; the area to be swept bythe hydrocarbon material of which the slug is formed;

the composition and physical properties of the slug maten rial; theinterstitial water present in the reservoir; the temperature and thepressure of the reservoir at the time of injection of the slug; theproperties of the oil in the reservoir to be driven out by the slug,such as the viscosity of the oil; the volume of the reservoir to beswept by the slug; and the distance between the input and outlet wells.The effect of some of these factors can be determined by core analysisof the reservoir and by other methods well known to those skilled in theart.

The above-mentioned factors, together with the freegas saturation in thereservoir, affect the length of the transistion zone between themiscible slug and the oil in the reservoir which is to be swept from thereservoir by the miscible slug. Referring to FIGURE l, this transitionzone, which contains a mixture of miscible material and reservoir oiland gas, is located in that portion of the reservoir in the area of theboundary between portion 11 and portion 12. It is in this transitionzone that the mixing occurs between the slug material and the reservoiroil. This transition zone varies with respect to the concentration ofslug material and reservoir oil. At the front of the slug, that is, thatpart in the slug adjacent to portion 11, there is a high reservoiroil-low slug material content, while this ratio changes moving towardthe slug material zone where it will be found there is a low reservoiroil-high slug material content. It is the length of this transition zonewhich is a major factor controlling the amount of miscible slug materialrequired to effect the desired removal of the reservoir oil.

Most of the above-discussed factors which affect the amount of thematerial making up the miscible slug are conditions which are inherentto the reservoir and are, therefore, not controllable. The matter of thefree-gas saturation of the hydrocarbon pore volume of the reservoir is,however, controllable, and in accordance with the invention, we havefound that the free-gas saturation has a major effect upon the amount ofslug material required. FIGURE 2 illustrates the relationship betweenthe percentage of free-gas saturation of the hydrocarbon pore volume ofthe reservoir and the quantity of material making up the miscible slugfor several systems tested. The effect of the percentage of free-gassaturation of the hydrocarbon pore volume of the reservoir upon therequired quantity of material in the miscible slug was investigated withtwo diffeernt gas-oil systems, namely, a 38 API gravity crudeoil-natural gas system and a Sovasol-methane system. Referring to FIG-URE 2, curve 20 represents the results of a test on a crude oil-naturalgas system; curve 21 represents a test made on a Sovasol-methane system;and curve 22 represents a test made on a Sovasol-methane system at areser- Voir pressure different from that at which the data for curve 21was obtained. Each of the curves in FIGURE 2 illustrates the minimumquantity of displacing uid required to effect oil production by slugaction or, in other words, without breakthrough of driving fluid priorto complete displacement of the oil. Stated otherwise, the curves inFIGURE 2 illustrate the minimum quantity of displacement uid needed tomaintain discrete slugs during production of substantially all the oilfrom the tubes employed in the test runs.

The tests which provided the data shown in FIGURE 2 were carried out ina sand-packed tube which was 50 feet long and had an inside diameter of0.305 inch. The sand employed in packing the tube had a particle sizecapable of passing through a 60-mesh screen. To obtain the datarepresented in curve 20, 38 API gravity crude oil containing dissolvednatural gas Was introduced into a sand-packed tube as above described.The viscosity of the crude oil containing the dissolved natural gas was1.5 centipoises at F. For the purpose of developing curve 20, a seriesof test runs were made in the tube with the free-gas saturation of thehydrocarbon system within the sand pack being at 2.0 percent, 16.3percent, 22.8 percent, 32.6 percent, 37.1 percent, and 39.4 percent,respectively. All of these test runs were made with the pressure withinthe tube being at approximately 1200 p.s.i., there existing a slightpressure differential between the ends of the tube to effect the desiredfluid flow through the tube. In order to carry out each of the runs, thesand pack was pressured to a high enough level to both establish aninitial condition of zero percent free-gas saturation within thehydrocarbon system in the sand pack and provide the desired percent offreegas saturation for the particular run when the pressure was reducedto 1200 p.s.i. In other words, the initial pressure for each run wassufficiently high that when the pressure was reduced to 1200 p.s.i. thedesired freegas saturation existed within the sand pack. For example, inmaking the first run the sand pack was initially pressured to a levelwhich established zero percent freegas saturation. This initial pressurelevel for this run was also sufficiently high that when the pressure wasreduced within the tube to 1200 p.s.i. the free-gas saturation was 2.0percent. Obviously, for the succeeding runs at the other free-gassaturations above enumerated, it was necessary that the initial pressurewithin the sand pack be somewhat greater than that for the 2 percentfree-gas saturation run in order that when the pressure was reduced to1200 p.s.i. the free-gas saturation would be at the desired level. Withrespect to each of these test runs, when the free-gas saturation wasestablished at the desired level at 1200 p.s.i., propane was introducedinto one end of the tube to serve as the miscible slug for displacingthe reservoir oil from the sand pack. The propane was driven through thetube to produce the oil from the sand pack. The content of thepropane-oil transition zone was measured by compositional analysis ofthe effiuent. For each of the runs, a determination was made of theminimum quantity of propane required to produce the oil from the tube byslug action without breakthrough of the driving fluid prior tosubstantially complete displacement of the oil from the sand pack.

Similar tests as described above were carried out in a sand-packed tubefor the Sovasol-methane systems as represented by curves 21 and 22 inFIGURE 2. Sovasol is a close-boiling naphtha of 300-400 F. boilingrange. The test was carried out at 1800 p.s.i. pressure with the sandpack being at 75 F. The viscosity of the Sovasolmethane system at thistemperature and pressure was 0.522 centipoise. The data on which curve21 is based was obtained by determining the propane content of thetransition zone between the oil and the propane for zero percent, 19.4percent, and 26.9 percent free-gas saturation. Curve 22 was obtained bytesting a Sovasol-methane system using the above-described procedure at1500 p.s.i. with the sand pack being at 75 F. During this latter testthe system was depressured by solution-gas drive to a free-gassaturation of 27.8 percent.

It is evident from an examination of FlGURE 2 that the optimum rangerequiring a minimum amount of miscible slug extends from approximately15 percent to about 30 percent free-gas saturation of the hydrocarbonpore volume. The advantage of operating in this optimum range isevidenced by the fact that at lower and higher free-gas saturations,that is, below about l5 percent and above about 30 percent, the quantityof miscible slug required is increased at least 40 percent above theminimum requirement within the desired range in accordance with ourinvention.

The third step in the process of our invention comprises theestbalishment of a driving uid Within reservoir behind the miscible slugdescribed in step 2 above. Referring to FIGURE 1, this driving uid isrepresented as filling portion 13 of reservoir 10. The driving fluid isintroduced into the reservoir through injection well 15. The driving uidintroduced in step 3 preferably is a fluid which is miscible with thehydrocarbon material forming the miscible slug described in step 2. Thedriving material of this step may be a ue gas, air, nitrogen, carbondioxide, or a relatively lean natural gas such as separator gas. Thedriving uidof this step is introduecd into the reservoir through Well ata pressure sufficient to establish miscibility, with the hydrocarbonmaterial of the miscible slug in order that the slug will be driventhrough the reservoir toward well 14. Injection of the driving iluid iscontinued at least until delivery of the miscible slug of step 2 iseffected at the outlet well 14, or until the effluent from well 14consists substantially of the driving uid. As the miscible slug isdriven through the formation, it picks up reservoir oil and gas andforces them from the reservoir through the outlet well. Y

Thus, it is seen that in accordance with out invention an oil-bearingreservoir is produced by solution-gas drive or other primary methods ofoil production until the hydrocarbon pore volume of the reservoircontains a freegas saturation within the range of approxrniately 15percent to about 30 percent, a slug of hydrocarbon material misciblewith the reservoir oil and gas is established in the reservoir, and adriving fluid is injected into the reservoir behind the miscible slugthus driving the miscible slug through the reservoir until the reservoiroil and gas are driven from the reservoir through an outlet Well.

What is claimed is: f

1. In a method of recovering oil from a subterranean reservoir providedwith at least one injection Well and at least one production well thesteps which comprise:

producing oil from said reservoirV by primary production until thefree-gas saturation within said reservoir 5 is within the range of about15 percent to about 30 percent of the hydrocarbon pore volume of saidreservoir; introducing into said reservoir through said injection well aquantity of fluid hydrocarbon material miscible with the oil remainingin said reservoir, said hydrocarbon material being injected at apressure suicient to establish miscibility with said oil; introducinginto said reservoir through said injection Well a driving fluid, saiddriving uid being miscible with said hydrocarbon material and beingintroduced at a pressure suicient to establish miscibility With saidhydrocarbon material;

forcing said oil and said hydrocarbon material through said reservoirtoward said production well by means of said driving fluid; and

producing oil from said reservoir through sa@ production Well. "Wi" 2.l'rrrethod of recovering oil from a subterranean reservoir provided withat least one injection well and at least one production well the stepswhich comprise:

producing Oil from Said feseryorhurmnmgilgmtiorrwuntil the free-gassaturation of said reservoir is within-the range of about 15 percent toabout 30 percent of the hydrocarbon pore volume of said reservoir;

introducing into said reservoir through said injection well ahydrocarbon uid miscible with the reservoir oil at the temperature andpressure existing within said reservoir, the quantity of said fluidranging from about 1 percent to about 10 percent of the hydrocarbon porevolume of said reservoir.

introducing into said reservoir through said injection well a driving@id misciblegwithpsaid hydrocarbon fluid, said driving fluid beingintroduced at a pressure suicient to establish miscibility with saidhydrocarbon fluid;

forcing said hydrocarbon fluid and said reservoir oil through saidreservoir toward said production Well by means of said driving Huid; and

producing said reservoir oil from said reservoir through said productionwell.

3. The method ,of claim 2 wherein the said hydrocarbon fluid is anenriched hydrocarbon gas.

4. The method of claim 2 wherein the said hydrocarbon uid is aliquefied, normally gaseous hydrocarbon material, said Huid beingintroduced at a pressure suicient to maintain said uid as a liquid slugwithin said reservoir.

References Cited in the tile of this patent FOREIGN PATENTS 696,524Great Britain Sept. 2, 1953

1. IN A METHOD OF RECOVERING OIL FROM A SUBTERRANEAN RESERVOIR PROVIDEDWITH AT LEAST ONE INJECTION WELL AND AT LEAST ONE PRODUCTION WELL THESTEPS WHICH COMPRISE; PRODUCING OIL FROM SAID RESERVOIR BY PRIMARYPRODUCTION UNITL THE FREE-GAS SATURATION WITHIN SAID RESERVOIR IS WITHINTHE RANGE OF ABOUT 15 PERCENT TO ABOUT 30 PERCENT OF THE HYDROCARBONPORE VOLUME OF SAID RESERVOIR; INTRODUCING INTO SAID RESERVOIR THROUGHSAID INJECTION WELL A QUANTITY OF FLUID HYDROCARBON MATERIAL MISCIBLEWITH THE OIL REMAINING IN SAID RESERVOIR, SAID HYDROCARBON MATERIALBEING INJECTED AT A PRESSURE SUFFICIENT TO ESTABLISH MISCIBILITY WITHSAID OIL;